1. Field of the Disclosure
This disclosure relates generally to apparatus and methods for determination of real-time hole cleaning and quantification of drilled cuttings during drilling of wellbores.
2. Background of the Art
Wellbores (also referred to herein as “wells” or “boreholes”) are drilled in subsurface formations for the production of hydrocarbons (oil and gas) trapped in zones at different depths. A large number of wells drilled exceed 15,000 feet and include relatively long deviated and horizontal sections. Such wells are drilled using a drill string that includes a drilling assembly (commonly referred to as the “bottomhole assembly” or “BHA”) at the bottom end of a drill pipe. The BHA includes a variety of sensors and devices and a drill bit attached at the bottom end of BHA. The drill string is conveyed into the well. To drill the well, the drill bit is rotated by rotating the drill string from the surface and/or by a mud motor placed in the BHA. A drilling fluid (commonly referred to as “mud”) is supplied under pressure from the surface into the drill pipe, which fluid discharges at the bottom of the drill bit and returns to the surface via the spacing between the drill string and the well (referred to as the “annulus”). The returning fluid (also referred to herein as the “return fluid”) contains the rock bits disintegrated by the drill bit, commonly referred to as the cuttings. The return fluid also sometimes contain gas and/or oil and/or water due to the influx from the formation. The return fluid, thus, often is a multiphase fluid with entrained solids. In horizontal and highly deviated wells, the cuttings sometime accumulate at the low side of such wells due to lack of adequate flow rate of the supplied drilling fluid and/or high density of the cuttings. At other times, the drilling fluid may enter the formation, in part, due to excessive overburden due to the weight of the fluid column in the wellbore or a relatively soft formation. At other times, the rock from the formation surrounding the wellbore may cave into the wellbore due to presence of a soft formation and/or high drilling fluid flow rate. When all the cuttings are removed as produced, the hole is said to be cleaning efficiently or effectively. Operators take remedial actions to alleviate the above-noted adverse conditions, once determined. The parameters controlled by the operator include the density of the fluid supplied to the wellbore and the flow rate of the supplied fluid. The density of the supplied fluid is controlled within a desired range to maintain a desired overburden
The present methods for measuring wellbore stability and influx from the formation commonly utilize Coriolis flow meters installed in the return line. These instruments are accurate when installed in a pipe that is completely full. However, the Coriolis flow meters are not always acceptably accurate when multi-phase fluid is present, such as fluid containing gas or when an air gap is present in the flow line. The air gap in the flow line sometimes is addressed by physically modifying the geometry of the return flow line that prevents the forming of the air gap.
The present methods for determining density of the return fluid for determining wellbore stability and hole cleaning efficiency utilizes a mass balance or scale that is affixed to the end of shale shakers installed to remove the solids from the return fluid. The shale shakers separate from the cuttings from the return fluid. The cuttings are passed to the mass balance to weigh the cuttings. The measured weight and/or volume of the cuttings is compared against the theoretical quantity of “dry” cuttings, as the weighted cuttings still include some amount of fluid. This method thus utilizes a correction factor that assumes the quantity of drilling fluid remaining in the cuttings when they are weighed.
It is important during drilling to maintain the drilling fluid density and thus equivalent circulating density (ECD) between the formation pore pressure and formation fracture gradient to avoid blow outs and fracturing of the formation. Too low ECD will likely yield an influx and possibly wellbore instability issues related to caving. Too high ECD will likely lead to fracturing of the formation and potentially loss of drilling fluid into the formation. The present methods for determining the desired drilling fluid density range involves calculations based on assumptions of formation depositions and original fluid type, i.e., saltwater in marine basins and their corresponding pressure gradients. These pore pressure models are adjusted with physical measurements, such as shale density. Shale density at depth is used to calculate an overburden gradient (OBG). Subsequently, Fracture Gradient and Pore Pressure Gradients are calculated using OBG determined from physical measurements instead of models. This results in more representative and accurate pore pressure calculations and increased insight and understanding into formation properties, leading to more successful drilling operations. These methods, however are not based on real time determination of density of the cuttings correlated to the wellbore depth. Thus, there is a need to determine in real time the density of the return fluid and the amount of cuttings in the return fluid that can be utilized to further determine other parameters, including desired drilling fluid density, pressure gradient, hole cleaning efficiency, gas/oil/water influx, caving, fracturing, and pore pressure.
The disclosure herein provides apparatus and methods for real time determination of density of the return fluid and the amount of cuttings in the return fluid from which other desired wellbore parameters may be determined.